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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-Q (Mark One)[X]
    
    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended September 30, 2004OR[ ]
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
 For the transition period from  to   Commission File Number 1-7584
 TRANSCONTINENTAL GAS PIPE LINE CORPORATION (Exact name of registrant as specified in its charter)
 Delaware
    
    74-1079400(State or other jurisdiction of
    
    (I.R.S. Employerincorporation or organization)
    
    Identification No.)2800 Post Oak BoulevardP. O. Box 1396Houston, Texas
    
    77251(Address of principal executive offices)
    
    (Zip Code)
 Registrants telephone number, including area code (713) 215-2000 None
(Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or15(d)of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [  ] Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [  ] No [X] The number of shares of Common Stock, par value $1.00 per share, outstanding as
of September 30, 2004 was 100. REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H (1)(a) AND
(b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED
DISCLOSURE FORMAT.




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION
INDEX  
 PagePART I. FINANCIAL INFORMATION:Item 1. Financial StatementsCondensed Consolidated Statement of Income for the three and nine months
ended September 30, 2004 and 2003
    
    
    2Condensed Consolidated Balance Sheet as of September 30, 2004 and
December 31, 2003
    
    
    3Condensed Consolidated Statement of Cash Flows for the nine
months ended September 30, 2004 and 2003
    
    
    5Notes to Condensed Consolidated Financial Statements
    
    
    6Item 2. Managements Narrative Analysis of the Results of Operations
    
    
    15Item 4. Controls and Procedures
    
    
    22PART II. OTHER INFORMATION
    
    
    23Item 1. Legal Proceedings
    
    
    23Item 6. Exhibits and Reports on Form 8-K
    
    
    23Section 302 CertificationSection 302 CertificationSection 306 Certification
  Certain matters discussed in this report, excluding historical
information, include forward-looking statements  statements that discuss our
expected future results based on current and pending business operations. We
make these forward-looking statements in reliance on the safe harbor
protections provided under the Private Securities Litigation Reform Act of
1995. Forward-looking statements can be identified by words such as
anticipates, believes, expects, planned, scheduled, could,
continues, estimates, forecasts, might, potential, projects or
similar expressions. Although we believe these forward-looking statements are
based on reasonable assumptions, statements made regarding future results are
subject to a number of assumptions, uncertainties and risks that may cause
future results to be materially different from the results stated or implied in
this document. Additional information about issues that could cause actual
results to differ materially from forward-looking statements is contained in
our 2003 Annual Report on Form 10-K and 2004 First and Second Quarter Reports
on Form 10-Q. 1




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PART 1  FINANCIAL INFORMATION 
 ITEM 1. Financial Statements. TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 CONDENSED CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003Operating Revenues:Natural gas sales
    
    $
    83,698
    
    
    $
    95,249
    
    
    $
    302,843
    
    
    $
    358,956Natural gas transportation
    
    
    187,276
    
    
    
    196,489
    
    
    
    586,630
    
    
    
    592,934Natural gas storage
    
    
    30,527
    
    
    
    31,384
    
    
    
    92,376
    
    
    
    94,350Other
    
    
    1,923
    
    
    
    1,476
    
    
    
    7,471
    
    
    
    15,306Total operating revenues
    
    
    303,424
    
    
    
    324,598
    
    
    
    989,320
    
    
    
    1,061,546Operating Costs and Expenses:Cost of natural gas sales
    
    
    83,698
    
    
    
    95,249
    
    
    
    301,294
    
    
    
    358,956Cost of natural gas transportation
    
    
    2,090
    
    
    
    9,160
    
    
    
    15,999
    
    
    
    19,803Operation and maintenance
    
    
    46,840
    
    
    
    45,401
    
    
    
    142,295
    
    
    
    137,550Administrative and general
    
    
    32,362
    
    
    
    28,332
    
    
    
    94,806
    
    
    
    83,366Depreciation and amortization
    
    
    47,815
    
    
    
    50,973
    
    
    
    144,436
    
    
    
    155,101Taxes - other than income taxes
    
    
    10,013
    
    
    
    9,979
    
    
    
    34,786
    
    
    
    30,610Other, net
    
    
    190
    
    
    
    (6,839
    )
    
    
    359
    
    
    
    (7,762
    )Total operating costs and expenses
    
    
    223,008
    
    
    
    232,255
    
    
    
    733,975
    
    
    
    777,624Operating Income
    
    
    80,416
    
    
    
    92,343
    
    
    
    255,345
    
    
    
    283,922Other (Income) and Other Deductions:Interest expense
    
    
    22,302
    
    
    
    22,346
    
    
    
    66,632
    
    
    
    66,691Interest income  affiliates
    
    
    (3,253
    )
    
    
    (718
    )
    
    
    (7,693
    )
    
    
    (3,990
    )Allowance for equity and borrowed funds used during construction (AFUDC)
    
    
    (2,525
    )
    
    
    (1,767
    )
    
    
    (5,870
    )
    
    
    (11,386
    )Equity in earnings of unconsolidated affiliates
    
    
    (1,787
    )
    
    
    (1,761
    )
    
    
    (5,306
    )
    
    
    (5,548
    )Miscellaneous other (income) deductions, net

    
    
    (1,999
    )
    
    
    (1,335
    )
    
    
    (3,773
    )
    
    
    (5,230
    )Total other (income) and other deductions
    
    
    12,738
    
    
    
    16,765
    
    
    
    43,990
    
    
    
    40,537Income before Income Taxes
    
    
    67,678
    
    
    
    75,578
    
    
    
    211,355
    
    
    
    243,385Provision for Income Taxes
    
    
    25,582
    
    
    
    28,256
    
    
    
    80,579
    
    
    
    93,279Net Income
    
    $
    42,096
    
    
    $
    47,322
    
    
    $
    130,776
    
    
    $
    150,106
 See accompanying notes. 2




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited) September 30,
    
    December 31,2004
    
    2003ASSETSCurrent Assets:Cash
    
    $
    121
    
    
    $
    300Receivables:Affiliates
    
    
    1,424
    
    
    
    9,360Advances to affiliates
    
    
    183,424
    
    
    
    49,947Others
    
    
    98,066
    
    
    
    133,814Transportation and exchange gas receivables
    
    
    19,301
    
    
    
    22,756Inventories
    
    
    109,230
    
    
    
    110,766Deferred income taxes
    
    
    18,830
    
    
    
    20,616Other
    
    
    16,176
    
    
    
    17,095Total current assets
    
    
    446,572
    
    
    
    364,654Investments, at cost plus equity in undistributed earnings
    
    
    43,422
    
    
    
    43,665Property, Plant and Equipment:Natural gas transmission plant
    
    
    5,832,008
    
    
    
    5,758,739Less-Accumulated depreciation and amortization
    
    
    1,557,087
    
    
    
    1,439,493Total property, plant and equipment, net
    
    
    4,274,921
    
    
    
    4,319,246Other Assets
    
    
    186,559
    
    
    
    205,862Total assets
    
    $
    4,951,474
    
    
    $
    4,933,427
 See accompanying notes. 3




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited) September 30,
    
    December 31,2004
    
    2003LIABILITIES AND STOCKHOLDERS EQUITYCurrent Liabilities:Payables:Affiliates
    
    $
    43,957
    
    
    $
    64,092Other
    
    
    52,786
    
    
    
    102,600Transportation and exchange gas payables
    
    
    23,588
    
    
    
    22,149Accrued liabilities
    
    
    124,447
    
    
    
    129,531Reserve for rate refunds
    
    
    8,669
    
    
    
    10,610Current maturities of long-term debt
    
    
    199,942
    
    
    
    Total current liabilities
    
    
    453,389
    
    
    
    328,982Long-Term Debt
    
    
    924,677
    
    
    
    1,123,958Other Long-Term Liabilities:Deferred income taxes
    
    
    971,475
    
    
    
    931,940Other
    
    
    112,370
    
    
    
    114,829Total other long-term liabilities
    
    
    1,083,845
    
    
    
    1,046,769Contingent liabilities and commitments (Note 2)Common Stockholders Equity:Common stock $1.00 par value:100 shares authorized, issued and outstanding
    
    
    
    
    
    
    Premium on capital stock and other paid-in capital
    
    
    1,652,430
    
    
    
    1,652,430Retained earnings
    
    
    838,208
    
    
    
    782,432Accumulated other comprehensive loss
    
    
    (1,075
    )
    
    
    (1,144
    )Total common stockholders equity
    
    
    2,489,563
    
    
    
    2,433,718Total liabilities and stockholders equity
    
    $
    4,951,474
    
    
    $
    4,933,427
 See accompanying notes. 4




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited) Nine Months EndedSeptember 30,2004
    
    2003Cash flows from operating activities:Net income
    
    $
    130,776
    
    
    $
    150,106Adjustments
to reconcile net income to net cash provided
by (used in) operating activities:Depreciation and amortization
    
    
    145,974
    
    
    
    151,488Deferred income taxes
    
    
    41,233
    
    
    
    16,258Allowance for equity funds used during construction
(Equity AFUDC)
    
    
    (4,170
    )
    
    
    (8,177
    )Changes in operating assets and liabilities:Receivables
    
    
    43,684
    
    
    
    31,315Transportation and exchange gas receivables
    
    
    3,455
    
    
    
    (10,514
    )Inventories
    
    
    1,536
    
    
    
    (49,983
    )Payables
    
    
    (47,240
    )
    
    
    (4,001
    )Transportation and exchange gas payables
    
    
    1,439
    
    
    
    12,016Accrued liabilities
    
    
    (5,084
    )
    
    
    (5,850
    )Reserve for rate refunds
    
    
    (1,941
    )
    
    
    2,555Other, net
    
    
    19,483
    
    
    
    (22,827
    )Net cash provided by operating activities
    
    
    329,145
    
    
    
    262,386Cash flows from financing activities:Debt issue costs
    
    
    
    
    
    
    (131
    )Change in cash overdrafts
    
    
    (13,195
    )
    
    
    (23,791
    )Common stock dividends paid
    
    
    (75,000
    )
    
    
    (205,000
    )Advances from affiliate, net
    
    
    
    
    
    
    (3,022
    )Net cash used in financing activities
    
    
    (88,195
    )
    
    
    (231,944
    )Cash flows from investing activities:Property, plant and equipment:Additions, net of equity AFUDC
    
    
    (99,445
    )
    
    
    (144,370
    )Changes in accounts payable
    
    
    (9,514
    )
    
    
    (981
    )Advances to affiliates, net
    
    
    (133,477
    )
    
    
    108,345Other, net
    
    
    1,307
    
    
    
    647Net cash used in investing activities
    
    
    (241,129
    )
    
    
    (36,359
    )Net decrease in cash
    
    
    (179
    )
    
    
    (5,917
    )Cash at beginning of period
    
    
    300
    
    
    
    6,183Cash at end of period
    
    $
    121
    
    
    $
    266
 See accompanying notes. 5




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION Transcontinental Gas Pipe Line Corporation (Transco) is a wholly-owned
subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned
subsidiary of The Williams Companies, Inc. (Williams). In this report, Transco (which includes Transcontinental Gas Pipe Line
Corporation and unless the context otherwise requires, all of our subsidiaries)
is at times referred to in the first person as we us or our. The condensed consolidated financial statements include our accounts and
the accounts of our majority-owned subsidiaries. Companies in which we and our
subsidiaries own 20 percent to 50 percent of the voting common stock or
otherwise exercise significant influence over operating and financial policies
of the company are accounted for under the equity method. The condensed consolidated financial statements have been prepared from
our books and records. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with accounting
principles generally accepted in the United States have been condensed or
omitted. The condensed unaudited consolidated financial statements include all
adjustments both normal recurring and others which, in the opinion of our
management, are necessary to present fairly our financial position at September
30, 2004, and results of operations for the three and nine months ended
September 30, 2004 and 2003, and cash flows for the nine months ended September
30, 2004 and 2003. These condensed consolidated financial statements should be
read in conjunction with the consolidated financial statements and the notes
thereto included in our 2003 Annual Report on Form 10-K and 2004 First and
Second Quarter Reports on Form 10-Q. As a participant in Williams cash management program, we have advances to
and from Williams. The advances are represented by demand notes. The interest
rate on intercompany demand notes is based upon the weighted average cost of
Williams debt outstanding at the end of each quarter. Prior to April 29, 2004,
the advances were made to and from our parent company, WGP. Through an agency agreement, Williams Power Company (WPC), an affiliate of
ours, manages all jurisdictional merchant gas sales for us, receives all
margins associated with such business and, as our agent, assumes all market and
credit risk associated with our jurisdictional merchant gas sales.
Consequently, our merchant gas sales service has no impact on our operating
income or results of operations. The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from
those estimates. Estimates and assumptions which, in the opinion of management,
are significant to the underlying amounts included in the financial statements
and for which it would be reasonably possible that future events or information
could change those estimates include: 1) revenues subject to refund; 2)
litigation-related contingencies; 3) environmental remediation obligations; 4)
impairment assessments of 6




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long-lived assets; 5) deferred and other income taxes; 6) depreciation; 7)
pensions and other post-employment benefits; and 8) asset retirement
obligations. Our Board of Directors declared cash dividends on common stock in the
amounts of $50 million on June 30, 2004 and $25 million on September 30, 2004. Comprehensive income for the three and nine months ended September 30,
2004 and 2003 respectively, are as follows (in thousands): Three Months
    
    Nine MonthsEnded September 30,
    
    Ended September 30,2004
    
    2003
    
    2004
    
    2003Net income
    
    $
    42,096
    
    
    $
    47,322
    
    
    $
    130,776
    
    
    $
    150,106Equity interest in
unrealized gain/(loss) on
interest rate hedge
    
    
    (287
    )
    
    
    343
    
    
    
    69
    
    
    
    290Total comprehensive income
    
    $
    41,809
    
    
    $
    47,665
    
    
    $
    130,845
    
    
    $
    150,396
 Recent accounting standardsEmerging Issues Task Force (EITF) Issue No.
03-1, The Meaning of Other Than Temporary Impairment and Its Application to
Certain Investments, contains recognition and measurement guidance that must
be applied to investment impairment evaluations. Specifically, the Issue
provides guidance to determine whether an investment is impaired and whether
that impairment is other than temporary. The Issue applies to debt and equity
securities, except equity securities accounted for under the equity method.
The Financial Accounting Standards Board (FASB) is currently considering
implementation guidance for the measurement and recognition provisions for this
Issue and has delayed implementation. This Issue is required to be adopted on
a prospective basis. We believe that the implementation of this Issue will not
have a material impact on our results of operations or financial position. In
March 2004, the FASB issued an exposure draft of an accounting
standard entitled
Share-Based Payment to amend Statement of Financial
Accounting Standards (SFAS) No. 123, Accounting for Stock-Based
Compensation, and SFAS No. 95, Statement of Cash Flows. At its October 13, 2004 meeting,
the FASB concluded that the final statement would be effective for any interim
or annual period beginning after June 15, 2005. At this time, we continue to
account for our stock-based compensation plans under Accounting Principles
Board Opinion No. 25 while applying the proforma disclosure requirements of
SFAS No. 148, Accounting for Stock-Based
Compensation  Transition and Disclosure (see Note 4). 2. CONTINGENT LIABILITIES AND COMMITMENTS Rate and Regulatory Matters General rate case (Docket No. RP01-245)On March 1, 2001, we submitted to
the Federal Energy Regulatory Commission (FERC) a general rate filing
principally designed to recover costs associated with an increase in rate base
resulting from additional plant, an increase in rate of return and related
taxes, and an increase in operation and maintenance expenses. In July, 2002, the FERC approved a Stipulation and Agreement (Settlement)
which resolved all cost of service, throughput and throughput mix issues in
this rate case proceeding with the exception of one cost of service issue
related to the valuation of certain right-of-way access for the installation of
a fiber optic system by a then Transco affiliate, the resolution of which is to
be applied prospectively. The other issues not resolved by the Settlement
include various cost allocation, rate design and tariff matters. 7




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On December 3, 2002, an Administrative Law Judge (ALJ) issued his initial
decision on the issues not resolved by the Settlement. In the initial decision,
the ALJ determined, among other things, that (1) our existing treatment of the
arrangement with our former affiliate relating to right of way is just and
reasonable, (2) our proposal to roll-in the costs of the Cherokee, Pocono and
SunBelt projects is unjust and unreasonable, and (3) our recovery of the costs
of the Mobile Bay expansion project on a rolled-in basis is unjust and
unreasonable. As to the Mobile Bay issue, the ALJ determined that we had the
burden of establishing that roll-in of that project is just and reasonable, but
did not address the issue of any potential refunds. Our current rates are
based on the roll-in of the Mobile Bay expansion project. On March 26, 2004, the FERC issued an order that affirmed, in part, and
reversed, in part, the ALJs initial decision on the issues not resolved by the
Settlement. On the issues discussed above, the FERC affirmed the ALJs
determination that our existing treatment of the arrangement with our former
affiliate relating to right of way is just and reasonable and our proposal to
roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and
unreasonable, but reversed the ALJs rejection of our proposal to recover the
costs of the Mobile Bay expansion project on a rolled-in basis and found that
we had shown that our proposed rolled-in rates are just and reasonable. The
FERC also affirmed the ALJs determination that we must separate our Emergency
Eminence Withdrawal service from our Rate Schedule FT service and offer the
Emergency Eminence Withdrawal service under a separate rate schedule, thereby
permitting shippers to decide whether to take that service. Currently, the
costs of the Emergency Eminence Withdrawal service is included as part of our
Rate Schedule FT service for those shippers that can access the Eminence
Storage Field. Under the FERCs decision, we would be at risk for those costs
to the extent that shippers did not elect to subscribe to all of the separately
offered service. Pursuant to the Settlement, this change, if upheld, would be
implemented on a prospective basis. On April 26, 2004, several parties,
including Transco, filed requests for rehearing of the FERCs March 26, 2004
order. General rate case (Docket No. RP97-71)On November 1, 1996, we submitted
to the FERC a general rate case filing principally designed to recover costs
associated with increased capital expenditures. The filing also included a pro-forma proposal to roll-in the costs of our
Leidy Line and Southern expansion incremental projects. All issues in this proceeding previously were resolved through settlement
or litigation, with the exception of the roll-in issues consolidated with
Docket No. RP95-197, which is discussed below. General rate case (Docket No. RP95-197)Through settlement and litigation,
all issues in this proceeding have been resolved, except a cost allocation
issue related to our implementation of the roll-in of the costs of our Leidy
Line and Southern Expansion projects. In April 1999, the FERC issued an order reversing a prior ALJ decision,
and concluded that we had demonstrated that our proposed rolled-in rate
treatment was just and reasonable. As a result, the FERC remanded to the ALJ
issues regarding the implementation of our roll-in proposal. Several parties
filed requests for rehearing of the FERCs order but their requests, as well as
subsequent court appeals, were denied. The ALJ generally ruled in favor of our implementation positions, with the
major exception that the ALJ required that the roll-in of the costs of the
incremental projects into Transcos system rates be phased in over a three-year
period. In October 2001, the FERC issued an order on the ALJs decision which
generally upheld the decision, except that the FERC reversed the ALJs decision
to phase the roll-in of the 8




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costs finding that the three-year phasing is not necessary in this case. In
August 2002, we filed to implement, among other things, the FERCs decision on
the roll-in of the costs of the incremental Leidy Line and Southern expansion
projects. On December 12, 2002, the FERC issued an order accepting our
compliance filing effective October 1, 2002. On January 13, 2003, certain
parties filed for rehearing of the FERCs December 12, 2002 order, arguing that
we improperly reallocated certain storage costs in implementing the roll-in. Gathering facilities spin-down order (Docket Nos. CP96-206-000 and
CP96-207-000)In 1996, we filed an application with the FERC for an order
authorizing the abandonment of certain facilities located onshore and offshore
in Texas, Louisiana and Mississippi by conveyance to an affiliate, Williams Gas
Processing  Gulf Coast Company (Gas Processing). The net book value of these
facilities at September 30, 2004, was approximately $340 million. Concurrently,
Gas Processing filed a petition for declaratory order requesting a
determination that its gathering services and rates be exempt from FERC
regulation under the NGA. The FERC issued an order dismissing our application
and Gas Processings petition for declaratory order and in 2001, the FERC
issued an order that denied our request for rehearing. Certain parties,
including us, filed in the United States Court of Appeals for the District of
Columbia Circuit (D.C. Circuit Court) petitions for review of the FERCs orders
and in June 2003, those petitions were denied. Several parties petitioned the
United States Supreme Court for review of the D.C. Circuit Courts opinion, and
on January 12, 2004, the Court denied those petitions. While the proceedings related to the 1996 application were pending, we
filed with the FERC the applications described below seeking authorization to
abandon portions of the facilities included in the 1996 application. North Padre Island/Central Texas Systems Spin-down Proceeding (Docket Nos.
CP01-32 and CP01-34)In 2000, we filed an application with the FERC seeking
authorization to abandon certain of our offshore Texas facilities by conveyance
to Gas Processing. Gas Processing filed a contemporaneous request that the FERC
declare that the facilities sought to be abandoned would be considered
nonjurisdictional gathering facilities upon transfer to Gas Processing. The
FERC approved the abandonment and the non-jurisdictional treatment of all of
these facilities. Effective December 2001, we transferred to Gas Processing the
North Padre Island facilities through a non-cash dividend of $3.3 million,
which represents the net book value of the facilities as of that date. Parties
filed petitions for review of the FERCs 2001 order to the D.C. Circuit Court
which were consolidated with the appeals of the FERCs orders in CP96-206 and
CP96-207, discussed above, and which were denied by the D.C. Circuit Court in
its opinion issued in June, 2003. In 2001, Shell Offshore, Inc. filed a
complaint at the FERC against Gas Processing, Williams Field Services Company
(WFS) and us alleging concerted actions by these affiliates frustrated the
FERCs regulation of us. The alleged actions are related to offers of gathering
service by WFS and its subsidiaries with respect to the North Padre Island
facilities. In 2002, the FERC issued an order reasserting jurisdiction over
that portion of the North Padre Island facilities previously transferred to
WFS. The FERC also determined a gathering rate for service on these
facilities, which is to be collected by us. Transco, Gas Processing and WFS
each sought rehearing of the FERCs order, and in May 2003, the FERC denied
those requests for rehearing. Transco, Gas Processing and WFS filed petitions
for review of the FERCs orders with the D.C. Circuit Court and on July 13,
2004, the court granted the petitions, vacating the FERCs orders and remanding
the case to the FERC for further proceedings not inconsistent with the courts
opinion. With regard to the approval of the spin-down of the Central Texas
facilities, a Transco customer filed a complaint with the FERC in Docket No.
RP02-309 seeking the revocation of the FERCs spin-down approval. In September
2002, the FERC issued an order requiring that, upon transfer of the Central
Texas 9




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facilities, we acquire capacity on the transferred facilities and provide
service to the existing customer under the original terms and conditions of
service. Our request for rehearing was denied in May 2003. The FERC also
required that we notify the FERC of Transcos plans with regard to the transfer
of the Central Texas facilities to Gas Processing. We replied that due to the
numerous outstanding issues affecting the transfer of those facilities, we
could not at that time predict the timing for the implementation of the
transfer of the Central Texas facilities. Transco and the customer each also
filed a request for rehearing of the FERCs May 2003 order. On May 6, 2004, the
FERC issued an order on rehearing effectively granting the customers request
for rehearing. On June 7, 2004, we filed a request for rehearing of the May 6,
2004 order, which the FERC denied on July 6, 2004. On July 14, 2004, we filed a
petition for review of the FERCs orders with the D.C. Circuit Court. At
September 30, 2004, the net book value of these facilities was $65 million
including the Williams purchase price allocation pushed down to Transco. North High Island/West Cameron Systems and Central Louisiana System
Spin-down ProceedingsIn 2001 the FERC issued orders authorizing us to spin
down only a portion of these systems to Gas Processing. All legal challenges of
these FERC orders have been exhausted and while we have not yet transferred any
of the facilities authorized for spin down to our gas processing affiliate, we
continue to evaluate the option of doing so. On May 6, 2004, the FERC issued an
order relating to the Central Louisiana system spin-down proceeding in which
the FERC required Transco and Gas Processing to show cause, due to developments
in another proceeding, why certain of the Central Louisiana facilities
previously found to be gathering should not be classified as jurisdictional
transmission facilities. We filed our response to the show cause order on July
6, 2004, arguing that the FERC should not alter its conclusion that the
facilities serve a gathering function. The net book value, at the application date, of the North High Island/West
Cameron and Central Louisiana facilities included in these two applications was
approximately $65 million including the Williams purchase price allocation
pushed down to Transco. South Texas Pipeline Facilities Abandonment ProceedingIn May 2003, the
FERC denied our request to abandon the South Texas pipeline facilities by sale
to a third party. On June 25, 2003, Transco and the third party purchaser
announced that they had agreed to terminate the purchase and sale agreement for
the facilities. On July 6, 2004, we executed another agreement to sell the
South Texas pipeline facilities to a third party, and on July 28, 2004, we
filed an application with the FERC for authorization to effectuate the sale.
The net book value of such facilities as of September 30, 2004 was
approximately $30 million, including the Williams purchase price allocation
pushed down to Transco. 1999 Fuel Tracker (Docket No. TM99-6-29)On March 1, 1999, we made our
annual filing pursuant to our FERC Gas Tariff to recalculate the fuel retention
percentages applicable to our transportation and storage rate schedules, to be
effective April 1, 1999. Included in the filing were two adjustments that
increased the estimated gas required for operations in prior periods by
approximately 8 billion cubic feet. Certain parties objected to the inclusion
of those adjustments and the FERC accepted the filing to be effective April 1,
1999, subject to refund and to further FERC action. In subsequent orders, the
FERC initially disallowed most of the adjustments, but later reconsidered that
decision and allowed us to make the adjustments, with the requirement we
collect the adjustments over a seven-year period. Although several of our
customers filed for rehearing of the FERCs decision to allow us to recover the
adjustments, the FERC denied the request for rehearing, and an appeal of the
FERCs decision was filed but later dismissed. In the second quarter of 2001,
we recorded a $15 million reduction in the cost of natural gas transportation
and reduced the related interest expense by $3 million to reflect the
regulatory approval to recover the cost of gas required for operations in prior
periods. 10




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The FERC then issued orders in which it addressed our proposed method for
recovering the permitted adjustments. The FERC determined that rather than
collecting the revenue (including interest) represented by the adjustments, we
should collect only the actual volumes comprising the adjustments. In the third
quarter of 2002, as a result of the FERCs determination, we recorded $3
million of interest expense that had been previously reduced in the second
quarter of 2001. Certain customers filed requests for rehearing of the FERCs
decision, and the FERC denied those requests. Several parties have filed a
joint petition for review in the D.C. Circuit Court of the FERCs order. In
accordance with the FERCs order, on January 21, 2004 we distributed refunds
and assessed surcharges to our customers for the period April 1, 1999 through
March 31, 2003. On March 10, 2004, we assessed further surcharges to our
customers covering the period April 1, 2003 through January 31, 2004. We
implemented the revised fuel retention factors resulting from application of
the FERCs order on a prospective basis beginning February 1, 2004. OtherWilliams, including Transco, responded to a subpoena from the
Commodities Futures Trading Commission (CFTC) and inquiries from the FERC
related to investigations involving natural gas storage inventory issues. On
August 30, 2004, the CFTC announced that it had concluded its investigation.
The FERC investigation is continuing. The FERC inquiries relate to the sharing
of non-public data concerning inventory levels and the potential uses of such
data in natural gas trading. We own and operate natural gas storage facilities. Legal Proceedings. Royalty claims and litigationIn connection with our renegotiations with
producers to resolve take-or-pay and other contract claims and to amend gas
purchase contracts, we entered into certain settlements which may require that
we indemnify producers for claims for additional royalties resulting from such
settlements. Through our agent WPC, we continue to purchase gas under contracts
which extend, in some cases, through the life of the associated gas reserves.
Certain of these contracts contain royalty indemnification provisions, which
have no carrying value. We have been made aware of demands on producers for
additional royalties and such producers may receive other demands which could
result in claims against us pursuant to royalty indemnification provisions.
Indemnification for royalties will depend on, among other things, the specific
lease provisions between the producer and the lessor and the terms of the
agreement between the producer and us. Consequently, the potential maximum
future payments under such indemnification provisions cannot be determined. As a result of these settlements, we have been sued by certain producers
seeking indemnification. We are currently a defendant in one such lawsuit.
Freeport-McMoRan, Inc., filed a lawsuit against us in the
19th Judicial
District Court in East Baton Rouge, Louisiana in which it asserted damages,
including interest calculated through September 30, 2004, of approximately $10
million. The case was tried in 2003 and resulted in a judgment favorable to
us, which Freeport-McMoRan is appealing. In 1998, the United States Department of Justice (DOJ) informed Williams
that Jack Grynberg, an individual, had filed claims in the United States
District Court for the District of Colorado under the False Claims Act against
Williams and certain of its wholly-owned subsidiaries including us. Mr.
Grynberg has also filed claims against approximately 300 other energy companies
and alleges that the defendants violated the False Claims Act in connection
with the measurement, royalty valuation and purchase of hydrocarbons. The
relief sought is an unspecified amount of royalties allegedly not paid to the
federal government, treble damages, a civil penalty, attorneys fees, and
costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui
tam cases, including the action filed against the Williams entities in the
United States 11




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District Court for the District of Colorado. In October 1999, the Panel on
Multi-District Litigation transferred all of the Grynberg qui tam cases,
including those filed against Williams, to the United States District Court for
the District of Wyoming for pre-trial purposes. In October 2002, the court
granted a motion to dismiss Grynbergs royalty valuation claims. Grynbergs
measurement claims remain pending against Williams, including us, and the other
defendants. Environmental Matters We are subject to extensive federal, state and local environmental laws
and regulations which affect our operations related to the construction and
operation of pipeline facilities. Appropriate governmental authorities enforce
these laws and regulations with a variety of civil and criminal enforcement
measures, including monetary penalties, assessment and remediation requirements
and injunctions as to future compliance. Our use and disposal of hazardous
materials are subject to the requirements of the federal Toxic Substances
Control Act (TSCA), the federal Resource Conservation and Recovery Act (RCRA)
and comparable state statutes. The Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA), also known as Superfund, imposes
liability, without regard to fault or the legality of the original act, for
release of a hazardous substance into the environment. Because these laws and
regulations change from time to time, practices that have been acceptable to
the industry and to the regulators have to be changed and assessment and
monitoring have to be undertaken to determine whether those practices have
damaged the environment and whether remediation is required. Since 1989, we
have had studies underway to test some of our facilities for the presence of
toxic and hazardous substances to determine to what extent, if any, remediation
may be necessary. We have responded to data requests from the U.S.
Environmental Protection Agency (EPA) and state agencies regarding such
potential contamination of certain of our sites. On the basis of the findings
to date, we estimate that over the next five years environmental assessment and
remediation costs under TSCA, RCRA, CERCLA and comparable state statutes will
total approximately $26 million to $30 million, measured on an undiscounted
basis. This estimate depends upon a number of assumptions concerning the scope
of remediation that will be required at certain locations and the cost of the
remedial measures. We are conducting environmental assessments and implementing
a variety of remedial measures that may result in increases or decreases in the
total estimated costs. At September 30, 2004, Transco had a balance of
approximately $26 million for these estimated costs recorded in current
liabilities ($5 million) and other long-term liabilities ($21 million) in the
accompanying Condensed Consolidated Balance Sheet. We consider prudently incurred environmental assessment and remediation
costs and costs associated with compliance with environmental standards to be
recoverable through rates. To date, we have been permitted recovery of
environmental costs, and it is our intent to continue seeking recovery of such
costs, through future rate filings. Therefore, these estimated costs of
environmental assessment and remediation have been recorded as regulatory
assets in current assets and other assets in the accompanying Condensed
Consolidated Balance Sheet. We have used lubricating oils containing polychlorinated biphenyls (PCBs)
and, although the use of such oils was discontinued in the 1970s, we have
discovered residual PCB contamination in equipment and soils at certain gas
compressor station sites. We have worked closely with the EPA and state
regulatory authorities regarding PCB issues, and we have a program to assess
and remediate such conditions where they exist, the costs of which are included
in the $26 million to $30 million range discussed above. We have been identified as a potentially responsible party (PRP) at
various Superfund and state waste disposal sites. Based on present volumetric
estimates and other factors, our estimated aggregate 12




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exposure for remediation of these sites is less than $500,000. The estimated
remediation costs for all of these sites have been included in the
environmental reserve discussed above. Liability under CERCLA (and applicable
state law) can be joint and several with other PRPs. Although volumetric
allocation is a factor in assessing liability, it is not necessarily
determinative; thus, the ultimate liability could be substantially greater than
the amounts described above. We are also subject to the federal Clean Air Act and to the federal Clean
Air Act Amendments of 1990 (1990 Amendments), which added significantly to the
existing requirements established by the federal Clean Air Act. The 1990
Amendments required that the EPA issue new regulations, mainly related to
stationary sources, air toxics, ozone non-attainment areas and acid rain.
During the last few years we have been installing new emission control devices
required for new or modified facilities in areas designated as non-attainment
by EPA. We operate some of our facilities in areas of the country currently
designated as non-attainment with the one-hour ozone standard. In April 2004,
EPA designated eight-hour ozone non-attainment areas. We also operate
facilities in areas of the country now designated as non-attainment with the
eight-hour ozone standard. Pursuant to non-attainment area requirements of the
1990 Amendments, and proposed EPA rules designed to mitigate the migration of
ground-level ozone (NOx) in 22 eastern states, we are planning installation of
air pollution controls on existing sources at certain facilities in order to
reduce NOx emissions. We anticipate that additional facilities may be subject
to increased controls within five years. For many of these facilities, we are
developing more cost effective and innovative compressor engine control
designs. Due to the developing nature of federal and state emission
regulations, it is not possible to precisely determine the ultimate emission
control costs. In March 2004 and June 2004, the EPA promulgated additional
regulations regarding hazardous air pollutants; these regulations may impose
controls in addition to the controls described above. The emission control
additions required to comply with current federal Clean Air Act requirements,
the 1990 Amendments, the hazardous air pollutant regulations, and the
individual state implementation plans for NOx reductions are estimated to
include costs in the range of $230 million to $260 million subsequent to 2003.
EPAs recent designation of new non-attainment areas will result in new federal
and state regulatory action that may impact our operations. As a result, the
cost of additions to property, plant and equipment is expected to increase. We
are unable at this time to estimate with any certainty the cost of additions
that may be required to meet new regulations, although it is believed that some
of those costs are included in the ranges discussed above. Management considers
costs associated with compliance with the environmental laws and regulations
described above to be prudent costs incurred in the ordinary course of business
and, therefore, recoverable through our rates. Safety Matters Pipeline Integrity RegulationsIn December 2003, the United States
Department of Transportation Office of Pipeline Safety issued a final rule
pursuant to the requirements of the Pipeline Safety Improvement Act of 2002
that was enacted in December 2002. The rule requires gas pipeline operators to
develop integrity management programs for transmission pipelines that could
affect high consequence areas in the event of pipeline failure, including a
baseline assessment and periodic reassessments to be completed within specified
timeframes. Currently, we estimate that the cost to perform required
assessments and repairs will be between $250 million and $300 million over the
2003 to 2012 period. Management considers the costs associated with compliance
with the rule to be prudent costs incurred in the ordinary course of business
and, therefore, recoverable through our rates. 13




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Summary Litigation, arbitration, regulatory matters, environmental matters and
safety matters are subject to inherent uncertainties. Were an unfavorable
ruling to occur, there exists the possibility of a material adverse impact on
the results of operations in the period in which the ruling occurs.
Management, including internal counsel, currently believes that the ultimate
resolution of the foregoing matters, taken as a whole and after consideration
of amounts accrued, insurance coverage, recovery from customers or other
indemnification arrangements, will not have a materially adverse effect upon
our future financial position. Other Commitments Commitments for constructionWe have commitments for construction and
acquisition of property, plant and equipment of approximately $59 million at
September 30, 2004. 3. DEBT AND FINANCING ARRANGEMENTS Revolving Credit and Letter of Credit Facilities On May 3, 2004, Williams entered into a new three-year $1 billion secured
revolving credit facility (Credit Agreement) which is available for borrowings
and letters of credit. In August 2004, Williams expanded the credit facility
by an additional $275 million. At September 30, 2004, letters of credit
totaling $438 million, none of which are associated with us, have been issued
by the participating institutions under this facility and no revolving credit
loans were outstanding. Transco and Northwest Pipeline Corporation, a
subsidiary of WGP, have access to $400 million each under the facility. The new
facility is secured by certain Williams midstream assets. Additionally, the
facility is guaranteed by WGP. Interest is calculated based on a choice of two
methods: a fluctuating rate equal to the facilitating banks base rate plus an
applicable margin or a periodic fixed rate equal to the London Interbank
Offering Rate (LIBOR) plus an applicable margin. Williams is also required to
pay a commitment fee based on the unused portion of the facility, currently
0.375%. The applicable margins and commitment fee are based on the relevant
borrowers senior unsecured long-term debt ratings. Current Maturities of Long-term Debt The current maturities of long-term debt at September 30, 2004 are
associated with $200 million of 6 1/8% Notes that mature on January 15, 2005.
It is managements intent to repay the notes from amounts due from Williams and
possibly a debt issuance. 4. STOCK-BASED COMPENSATION Employee stock-based awards are accounted for under Accounting Principles
Board Opinion No. 25, Accounting for Stock Issued to Employees and related
interpretations. Williams fixed-plan common stock options generally do not
result in compensation expense because the exercise price of the stock options
equals the market price of the underlying stock on the date of grant. The
following table illustrates the effect on net income if we had applied the fair
value recognition provisions of Statement of Financial Accounting Standards
(SFAS) No. 123,Accounting for Stock-Based Compensation (in thousands). 14




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Three Months
    
    Nine MonthsEnded September 30,
    
    Ended September 30,2004
    
    2003
    
    2004
    
    2003Net income, as reported
    
    $
    42,096
    
    
    $
    47,322
    
    
    $
    130,776
    
    
    $
    150,106Add/Dedect: Stock-based employee compensation included in
the Condensed Consolidated Statement of Income, net of
related tax effects
    
    
    111
    
    
    
    
    
    
    
    295
    
    
    
    (55
    )Deduct: Stock-based employee compensation expense
determined under fair values based method for all awards, net
of related tax effects
    
    
    (1,090
    )
    
    
    (523
    )
    
    
    (2,440
    )
    
    
    (1,499
    )Pro forma net income
    
    $
    41,117
    
    
    $
    46,799
    
    
    $
    128,631
    
    
    $
    148,552
 Pro forma amounts for 2004 include compensation expense from awards made
in 2004, 2003, 2002 and 2001. Also included in pro forma expense for the three
and nine months ended September 30, 2004, is $0.2 million and $0.5 million,
respectively, of incremental expense associated with the stock option exchange
program discussed below. Pro forma amounts for 2003 include compensation
expense from awards made in 2003, 2002 and 2001. Since compensation expense for stock options is recognized over the future
years vesting period for pro forma disclosure purposes and additional awards
are generally made each year, pro forma amounts may not be representative of
future years amounts. On May 15, 2003, Williams shareholders approved a stock option exchange
program. Under this program, eligible employees were given a one-time
opportunity to exchange certain outstanding options for a proportionately
lesser number of options at an exercise price to be determined at the grant
date of the new options. Surrendered options were cancelled June 26, 2003, and
replacement options were granted on December 29, 2003. We did not recognize any
expense pursuant to the stock option exchange. However, for purposes of pro
forma disclosures, we recognized additional expense related to these new
options and will amortize the remaining expense on the cancelled options
through year-end 2004. 
 ITEM 2. Managements Narrative Analysis of the Results of Operations. Regulatory Matters Order Nos. 2004, et seq. (Docket No. RM01-10-000)On November 25, 2003,
the FERC issued Order No. 2004 adopting uniform standards of conduct for
transmission providers. The proposed rules define transmission providers as
interstate natural gas pipelines and public utilities that own, operate or
control electric transmission facilities. The standards regulate the conduct of
transmission providers with their energy affiliates. In Order No. 2004, the
FERC defined energy affiliates broadly to include any non-transmission provider
affiliate that engages in or is involved in transmission (gas or electric)
transactions, manages or controls transmission capacity or that buys, sells,
trades or administers natural gas or electric energy, engages in financial
transactions relating to the sale or transmission of natural gas or
electricity, and Hinshaw and intrastate pipelines. In Order No. 2004-A, issued
on April 16, 2004, the FERC, among other things, clarified the definition of
energy affiliates in a manner that narrowed its scope. On August 2, 2004, the
FERC issued Order No. 2004-B, which, among other things, further clarified the
definition of energy affiliates and deferred the implementation date for the
new standards of conduct until September 22, 2004. We posted our procedures
implementing the requirements of Order No. 2004 on September 22, 2004, in
compliance with the new standards of conduct. 15




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Beginning in May 1995, Williams Field Services Company (WFS), an
affiliated company, operated our production area facilities pursuant to the
terms of an operating agreement. In response to FERC Order No. 2004, we
terminated the operating agreement and effective June 1, 2004, we resumed
operating these facilities. We anticipate that the increased costs resulting
from the additional employees required to operate these facilities will be
offset by the discontinuation of the operating fee we were paying to WFS under
the terms of the operating agreement. General The following discussion should be read in conjunction with the
consolidated financial statements, notes and managements narrative analysis
contained in Items 7 and 8 of our 2003 Annual Report on Form 10-K and in our
2004 First and Second Quarter Reports on Form 10-Q and with the condensed
consolidated financial statements and notes contained in this report. RESULTS OF OPERATIONS Operating Income and Net Income Our operating income for the nine months ended September 30, 2004 was
$255.3 million compared to operating income of $283.9 million for the nine
months ended September 30, 2003. Net income for the nine months ended September
30, 2004 was $130.8 million compared to $150.1 million for the nine months
ended September 30, 2003. The lower operating income of $28.6 million was
primarily the result of lower transportation revenues, lower other operating
revenues, higher administrative and general cost and higher other operating
expenses, partially offset by lower depreciation and amortization expense as
discussed below. The decrease in net income of $19.3 million was attributable
to the decreased operating income and higher net expenses as discussed below in
Other Income and Other Deductions. Transportation Revenues Our operating revenues related to transportation services for the nine
months ended September 30, 2004 were $586.6 million, compared to $592.9 million
for the nine months ended September 30, 2003. The lower transportation revenues
of $6.3 million were primarily due to a decrease of $15.7 million of
reimbursable costs that are included in operating expenses and recovered in our
rates and a $4.6 million decrease in commodity revenues which is due primarily
to lower interruptible transportation. This was partially offset by increased
demand revenues of $14.3 million mostly resulting from new expansion projects
(Momentum Phase 1 placed into service on May 1, 2003, Trenton-Woodbury placed
into service on November 1, 2003, and Momentum Phase 2 placed into service on
February 1, 2004). As shown in the table below, our total market-area deliveries for the nine
months ended September 30, 2004 increased 29.0 trillion British Thermal Units
(TBtu) (2.5%) when compared to the same period in 2003. Increased deliveries
were associated with an increase in power generation relative to the same
period in 2003. Our production area deliveries for the nine months ended
September 30, 2004 increased 26.9 TBtu (12.2%) when compared to the same period
in 2003. This is primarily due to increased deliveries to production area
interconnects and increased deliveries to production area processing plants. 16




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Nine MonthsEnded September 30,Transco System Deliveries (TBtu)
    
    2004
    
    2003Market-area deliveries:Long-haul transportation
    
    
    582.0
    
    
    
    578.1Market-area transportation
    
    
    609.2
    
    
    
    584.1Total market-area deliveries
    
    
    1,191.2
    
    
    
    1,162.2Production-area transportation
    
    
    246.6
    
    
    
    219.7Total system deliveries
    
    
    1,437.8
    
    
    
    1,381.9Average Daily Transportation Volumes (Tbtu)
    
    
    5.2
    
    
    
    5.1Average Daily Firm Reserved Capacity (Tbtu)
    
    
    6.6
    
    
    
    6.4
 Our facilities are divided into eight rate zones. Five are located in the
production area and three are located in the market area. Long-haul
transportation is gas that is received in one of the production-area zones and
delivered in a market-area zone. Market-area transportation is gas that is both
received and delivered within market-area zones. Production-area transportation
is gas that is both received and delivered within production-area zones. Sales Revenues We make jurisdictional merchant gas sales to customers pursuant to a
blanket sales certificate issued by the FERC, with most of those sales being
made through a Firm Sales (FS) program which gives customers the option to
purchase daily quantities of gas from us at market-responsive prices in
exchange for a demand charge payment. Pursuant to the terms of an agreement
with the FERC which resolved an open investigation, we have notified our
merchant sales customers that we will be terminating the merchant sales service
when we are able to do so under the terms of any applicable contracts and FERC
certificates authorizing such services. Under the FS program we must provide
two-year advance notice of termination. Therefore, we notified the FS customers
of our intention to terminate the FS service effective April 1, 2005. Through an agency agreement, WPC manages our jurisdictional merchant gas
sales, excluding our cash out sales in settlement of gas imbalances. The
long-term purchase agreements managed by WPC remain in our name, as do the
corresponding sales of such purchased gas. Therefore, we continue to record
natural gas sales revenues and the related accounts receivable and cost of
natural gas sales and the related accounts payable for the jurisdictional
merchant sales that are managed by WPC. WPC receives all margins associated
with jurisdictional merchant gas sales business and, as our agent, assumes all
market and credit risk associated with our jurisdictional merchant gas sales.
Consequently, our merchant gas sales service has no impact on our operating
income or results of operations and, therefore, the anticipated termination of
such services in April 2005, will have no impact on our operating income or
results of operations. In addition to our merchant gas sales, we also have cash out sales, which
settle gas imbalances with shippers. The cash out sales have no impact on our
operating income or results of operations. Operating revenues related to our sales services were $302.8 million for
the nine months ended September 30, 2004, compared to $359.0 million for the
same period in 2003. The decrease was primarily due to a lower volume of
merchant sales during the first nine months of 2004 compared to the same period
in 2003. This was partially offset by increases resulting from higher cash out
sales volumes related to the 17




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monthly settlement of imbalances and a higher average sales price of $5.93
per dekatherm (dt) for the nine months ending September 30, 2004 compared to
$5.66 for the same period of 2003. Nine MonthsEnded September 30,Gas Sales Volumes (Tbtu)
    
    2004
    
    2003Long-term sales
    
    
    25.0
    
    
    
    31.9Short-term sales
    
    
    10.6
    
    
    
    18.9Total gas sales
    
    
    35.6
    
    
    
    50.8
 Storage Revenues Our operating revenues related to storage services of $92.4 million for
the nine months ended September 30, 2004 were comparable to revenues of $94.4
million for the same period in 2003. Other Revenues Our other operating revenues were $7.5 million for the nine months ended
September 30, 2004 compared to $15.3 million for the same period in 2003. The
reduction was primarily due to a decrease in the sale of environmental
mitigation credits. Operating Costs and Expenses Excluding the cost of natural gas sales of $301.3 million for the nine
months ended September 30, 2004 and $359.0 million for the comparable period in
2003, our operating expenses for the nine months ended September 30, 2004, were
approximately $14.0 million higher than the comparable period in 2003. This was
attributable to increases in operation and maintenance expenses, administrative
and general expenses, taxes other than income taxes and other operating costs
and expenses, partially offset by lower cost of natural gas transportation and
depreciation and amortization expense. The increase in operation and
maintenance expense in 2004 of $4.7 million is due primarily to increased
materials and supplies cost of $3.1 million and higher maintenance cost of $1.3
million for right-of-way clearing. The increase in administrative and general
expense of $11.4 million is mostly due to increased management services billed
to us by Williams. As a result of recent changes within Williams, we are
receiving an increased share of the management services allocation. The higher
management services are also due to increased third-party costs associated with
Sarbanes-Oxley Act compliance activities and with efforts at Williams to
evaluate and implement certain cost reduction strategies through internal
initiatives and outsourcing of certain services. The $4.2 million increase in
taxes other than income taxes was mostly due to an increase in franchise taxes
in the various states in which we operate. The higher other operating costs and
expenses of $8.1 million were primarily due to a reduction of accrued
liabilities in the third quarter of 2003 for claims associated with certain
producer indemnities. The lower cost of natural gas transportation of $3.8
million resulted from a decrease of $12.9 million in 2004 of reimbursable costs
that are recovered in our rates and a $4.0 million charge in the third quarter
of 2003 associated with the write-off of certain receivables. These decreases
were partially offset by an increase in fuel expense of $13.1 million due to
the benefit of pricing differentials in 2003 related to volumes of gas used in
operations. The lower depreciation and amortization expense of $10.7 million
was due to decreases of $4.9 million associated with lower environmental
mitigation development costs, $4.0 million resulting from an adjustment to
depreciation previously recognized and $1.8 million due primarily to decreased
computer software and hardware assets. 18




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Other Income and Other Deductions Other income and other deductions for the nine months ended September 30,
2004 resulted in higher net expenses of $3.5 million compared to the same
period in 2003. This was primarily due to a decrease in the allowance for funds
used during construction resulting from a lower amount of capital projects
under construction. CAPITAL RESOURCES AND LIQUIDITY Method of Financing We fund our capital requirements with cash flows from operating
activities, by repayments of funds advanced to Williams, by accessing capital
markets, and, if required, by borrowings under the Credit Agreement and
advances from Williams. We have an effective registration statement on file with the Securities
and Exchange Commission. At September 30, 2004, $200 million of shelf
availability remains under this registration statement which may be used to
issue debt securities. However, the ability to utilize this registration
statement is restricted by certain covenants of Williams debt agreements.
Interest rates, market conditions, and industry conditions will affect amounts
borrowed, if any, under this arrangement. We believe any additional financing
arrangements, if required, can be obtained from the capital markets on terms
that are commensurate with our current credit ratings. On May 3, 2004, Williams entered into a new three-year $1 billion secured
revolving credit facility which is available for borrowings and letters of
credit. In August 2004, Williams expanded the credit facility by an additional
$275 million. At September 30, 2004, letters of credit totaling $438 million,
none of which are associated with us, have been issued by the participating
institutions under this facility and no revolving credit loans were
outstanding. Transco and Northwest Pipeline Corporation, a subsidiary of WGP,
have access to $400 million each under the facility. The new facility is
secured by certain Williams midstream assets. Additionally, the facility is
guaranteed by WGP. Interest is calculated based on a choice of two methods: a
fluctuating rate equal to the facilitating banks base rate plus an applicable
margin or a periodic fixed rate equal to LIBOR plus an applicable margin.
Williams is also required to pay a commitment fee based on the unused portion
of the facility, currently 0.375%. The applicable margins and commitment fee
are based on the relevant borrowers senior unsecured long-term debt ratings. As a participant in Williams cash management program, we have advances to
and from Williams. At September 30, 2004, the advances due to us by Williams
totaled $183.4 million. The advances are represented by demand notes. We
anticipate demanding repayment of a significant portion of these advances to
Williams for use in retiring the $200 million of 6 1/8% Notes that mature on
January 15, 2005. Effective September 2003, the interest rate on intercompany
demand notes is based upon the weighted average cost of Williams debt
outstanding at the end of each quarter. Previously, the interest rate on
intercompany demand notes was based on the LIBOR plus an applicable margin.
Williams has indicated that it currently believes that it will continue to have
the financial resources and liquidity to repay these advances. Prior to April
29, 2004, the advances were made to and from our parent company, WGP. 19




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Williams Recent Events In February 2003, Williams outlined its planned business strategy in
response to the events that significantly impacted the energy sector and
Williams during late 2001 and much of 2002. The plan focused on migrating to an
integrated natural gas business comprised of a strong, but smaller portfolio of
natural gas businesses, reducing debt and increasing Williams liquidity
through assets sales, strategic levels of financing and reductions in operating
costs. The plan was designed to address near-term and medium-term debt and
liquidity issues, to de-leverage Williams with the objective of returning to
investment grade status and to develop a balance sheet and cash flows capable
of supporting and ultimately growing its remaining businesses. As discussed in our Annual Report on Form 10-K for the year ended December
31, 2003, Williams successfully executed certain critical components of its
plan during 2003. Key execution steps for 2004 and beyond included the
completion of planned asset sales, additional reductions of Williams selling,
general and administrative (SG&A) costs, the replacement of its
cash-collateralized letter of credit and revolver facility with facilities that
do not encumber cash and continuation of efforts to exit from the power
business. Asset sales during 2004 were expected to generate proceeds of
approximately $800 million. In the first quarter of 2004, Williams completed an
asset sale for approximately $304 million. In July 2004, Williams completed the
sale of additional assets for approximately $544 million, including amounts
paid to its subsidiaries for amounts previously due from the assets that were
sold. In September 2004, Williams Board of Directors approved the decision to
retain Williams power business and end its efforts to exit that business.
Williams will continue its current program of managing this business to
minimize financial risk and maximize cash flow associated with its long-term
contracts. Credit Ratings The credit ratings on our senior unsecured long-term debt did not change
during the first nine months of 2004 and, as of September 30, 2004, are as
follows: Moodys Investors Services
    
    B1Standard & Poors
    
    B+Fitch Ratings
    
    BB
 Capital Expenditures As shown in the table below, our capital expenditures for the nine months
ended September 30, 2004 were $109.0 million, compared to $145.4 million for
the nine months ended September 30, 2003. We currently estimate that capital
expenditures for the year 2004 will be approximately $160 million compared to
the approximately $191 million detailed in our 2003 Annual Report on Form 10-K. 20




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Nine MonthsEnded September 30,Capital Expenditures
    
    2004
    
    2003(In Millions)Market-area projects
    
    $
    11.3
    
    
    $
    90.9Supply-area projects
    
    
    6.1
    
    
    
    11.0Maintenance of existing facilities and other projects
    
    
    91.6
    

    
    
    43.5Total capital expenditures
    
    $
    109.0
    
    
    $
    145.4
 Our capital expenditures estimate for 2004 and future capital projects are
discussed in our 2003 Annual Report on Form 10-K and 2004 First and Second
Quarter Reports on Form 10-Q. The following describes new capital projects
proposed by us. Central New Jersey Expansion ProjectThe Central New Jersey Expansion
Project will involve an expansion of our existing natural gas transmission
system in Zone 6 from the Station 210 pooling point to locations along our
Trenton-Woodbury Line. The project will create 105,000 dekatherms per day
(dt/d) of new firm transportation capacity, which has been fully subscribed by
one shipper for a twenty-year primary term. The project facilities will include
approximately 3.5 miles of pipeline loop at an estimated capital cost of $13
million. We filed an application for FERC approval of the project on August 11,
2004. The target in-service date for the project is November 1, 2005. Leidy to Long Island Expansion ProjectWe held an open season from June
14, 2004 to July 13, 2004 to receive requests for new firm transportation
capacity to be made available from the Leidy Hub in Clinton County,
Pennsylvania to certain Zone 6 delivery points under our proposed Leidy to Long
Island Expansion Project. As a result of the open season, the expansion has
been designed to create 100,000 dt/d of firm transportation capacity, for which
one shipper has submitted a binding commitment for a twenty-year primary term.
The current design of the project facilities includes pipeline looping and
compression facilities and pipeline and compressor upgrades at an estimated
capital cost of approximately $143 million. The final design of the project
facilities is subject to the outcome of our reverse open season solicitation
of permanent capacity release offers. We expect that nearly three-quarters of
the project expenditures will occur in 2007. We plan to file for FERC approval
of the project in the third quarter of 2005. The target in-service date for the
project is November 1, 2007. Other Capital Requirements and Contingencies Our capital requirements and contingencies are discussed in our 2003
Annual Report on Form 10-K. Other than as described in Note 2 of the Notes to
Condensed Consolidated Financial Statements and the Capital Expenditures
discussion in Item 2 of this report, there have been no new developments from
those described in our 2003 Annual Report on Form 10-K and 2004 First and
Second Quarter Reports on Form 10-Q with regard to other capital requirements
and contingencies. Conclusion Although no assurances can be given, we currently believe that the
aggregate of cash flows from operating activities, supplemented, when
necessary, by repayments of funds advanced to Williams, advances or capital
contributions from Williams and borrowings under the Credit Agreement will
provide us with sufficient liquidity to meet our capital requirements. When
necessary, we also expect to access public and private markets on terms
commensurate with our current credit ratings to finance our capital
requirements. 21




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ITEM 4. Controls and Procedures. An evaluation of the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rule 13a-15(e) and 15(d)-(e)
of the Securities Exchange Act) (Disclosure Controls) was performed as of the
end of the period covered by this report. This evaluation was performed under
the supervision and with the participation of our management, including our
Senior Vice President and Vice President and Treasurer. Based upon that
evaluation, our Senior Vice President and Vice President and Treasurer
concluded that these Disclosure Controls are effective at a reasonable
assurance level. Our management, including our Senior Vice President and Vice President and
Treasurer, does not expect that our Disclosure Controls or our internal
controls over financial reporting (Internal Controls) will prevent all errors
and all fraud. A control system, no matter how well conceived and operated, can
provide only reasonable, not absolute, assurance that the objectives of the
control system are met. Further, the design of a control system must reflect
the fact that there are resource constraints, and the benefits of controls must
be considered relative to their costs. Because of the inherent limitations in
all control systems, no evaluation of controls can provide absolute assurance
that all control issues and instances of fraud, if any, within the company have
been detected. These inherent limitations include the realities that judgments
in decision-making can be faulty, and that breakdowns can occur because of
simple error or mistake. Additionally, controls can be circumvented by the
individual acts of some persons, by collusion of two or more people, or by
management override of the control. The design of any system of controls also
is based in part upon certain assumptions about the likelihood of future
events, and there can be no assurance that any design will succeed in achieving
its stated goals under all potential future conditions. Because of the inherent
limitations in a cost-effective control system, misstatements due to error or
fraud may occur and not be detected. We monitor our Disclosure Controls and
Internal Controls and make modifications as necessary; our intent in this
regard is that the Disclosure Controls and the Internal Controls will be
modified as systems change and conditions warrant. Effective July 1, 2004, Williams entered into an outsourcing agreement
with IBM which will improve Williams ability to adjust support operations as
business conditions dictate while maintaining a high quality of service. The
services being rendered by IBM include certain aspects of Williams accounting,
human resources and information technology activities. The more significant of
these include payroll, accounts payable, property, general ledger and related
accounting, benefits, compensation, infrastructure and applications. As a
result of the outsourcing substantially all of Williams employees in the
outsourced functions were initially hired by IBM and continued performing the
same functions during the third quarter. Contractually, IBM is required to
develop and implement internal controls and has agreed to work with Williams to
implement compliance measures to satisfy the Sarbanes-Oxley Act of 2002. IBM
has agreed to make minimal changes to processes and systems through year end
2004. Notwithstanding the above, management concludes that its current controls
are effective at a reasonable assurance level. In addition, there has been no
material change, other than the outsourcing described above, in our Internal
Controls that occurred during the registrants third fiscal quarter. 22




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PART II  OTHER INFORMATION 
 ITEMS 1. LEGAL PROCEEDINGS. See discussion in Note 2 of the Notes to Condensed Consolidated
Financial Statements included herein. 
 ITEM 6. EXHIBITS.  The following instruments are included as exhibits to
this report. Those exhibits below incorporated by reference
herein are indicated as such by the information supplied in
the parenthetical thereafter. If no parenthetical appears
after an exhibit, copies of the instrument have been included
herewith.  (10)
    
    Material contracts  
    1
    Letter of Credit Commitment Increase Agreement dated August 4, 2004,
by and among The Williams Companies, Inc., Citicorp USA in its
capacity as Agent under the Credit Agreement dated as of May 3, 2004
among the Borrower, Northwest Pipeline Corporation, Transcontinental
Gas Pipe Line Corporation, the Agent, the Collateral Agent, the Banks
and Issuing Banks party thereto and Citibank, N.A. and Bank of
America, N.A. (filed as Exhibit 10.1 to The Williams Companies, Inc.
Form 10-Q for the quarter ended September 30, 2004 Commission File
Number 1-4174).
    2
    Revolving Credit Commitment Increase Agreement dated August 4, 2004,
by and among the Williams Companies, Inc., Citicorp USA, Inc. in its
capacity as Agent under the Credit Agreement dated as of May 3, 2004
among the Borrower, Northwest Pipeline Corporation, Transcontinental
Gas Pipe Line Corporation, the Agent, the Collateral Agent and the
Banks and Issuing Banks party thereto, the Issuing Banks and Citicorp
USA, Inc. (filed as Exhibit 10.2 to The Williams Companies, Inc. Form
10-Q for the quarter ended September 30, 2004 Commission File Number
1-4174).  (31)
    
    Section 302 Certifications  
    1
    Certification of Principal Executive Officer pursuant to
Rules 13a-14(a) and 15d-14(a) promulgated under the
Securities Exchange Act of 1934, as amended, and Item
601(b)(31) of Regulation S-K, as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.
    2
    Certification of Principal Financial Officer pursuant to
Rules 13a-14(a) and 15d-14(a) promulgated under the
Securities Exchange Act of 1934, as amended, and Item
601(b)(31) of Regulation S-K, as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.  (32)
    
    Section 906 Certification  1
    Certification of Principal Executive
Officer and Principal Financial Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002. 23




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SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. TRANSCONTINENTAL GAS PIPE LINECORPORATION (Registrant)Dated: November 4, 2004
    
    By
    
    /s/ Jeffrey P. HeinrichsJeffrey P. HeinrichsController(Principal Accounting Officer)
 24